Gas streams can be treated in numerous manners to reduce acid gas content (e.g., H2S and/or CO2), typically using a solvent with more or less pronounced selectivity towards a specific acid gas component. Unfortunately, many gas streams also contain considerable quantities of non-acid gas contaminants, and particularly mercaptans and other sulfurous species (e.g. lower alkyl mercaptans, carbonyl sulfide, dimethyl disulfide, carbon disulfide, propanethiol, thiophene, etc.), which tend to participate in undesirable side reactions with the solvent. As a consequence of such reactions, solvent processing, replacement and/or additives to reduce corrosion and inhibitor formation are often required. Alternatively, in other known configurations, pre- and post treatment units are needed to render the gas stream suitable for further processing.
One exemplary known gas treatment configuration that employs a physical solvent is depicted in Prior Art FIG. 1 in which the acid gases are absorbed in an absorber that forms a rich solvent. The rich solvent is then flashed in a flash drum with the vapors being recycled to the absorber while the liquid is routed to the regenerator. Here, the acid gases are removed from the solvent to form the lean solvent that is cross exchanged with the rich solvent before re-entering the absorber. The so removed acid gases and other sulfurous compounds are then processed in a three-phase separator to form a reflux for the regenerator, a contaminant vapor, and a contaminant liquid. Contaminant gases are typically further processed in a Claus plant, while contaminant liquids are usually fed to a refinery for subsequent treatment (e.g., in a hydrotreater). Most commonly, solvents are selected physical solvents or amine solvents (e.g. propylene carbonate, tributyl phosphate, methylpyrolidone, polyethylene glycol dialkyl ethers, formulated tertiary amines, etc.) that can be used to remove at least some of the mercaptans and heavy hydrocarbons from the feed gas.
While such processes generally satisfy sulfur removal requirements for various feed gases, several problems nevertheless remain. Most significantly, processing requirements for the sulfurous species to avoid acid gas emission are typically only shifted to a downstream location. For example, hydrotreating of the mercaptans laden liquids in an existing refinery unit may over-burden the process equipment, and will most often require modification of such equipment. Also, the non-H2S sulfur-containing compounds in the gases to the sulfur plant will often create conversion problems in the sulfur plant. Among other things, for high rates of thermal destruction of mercaptans and the organic sulfurs contaminants, the Claus reaction furnace needs to operate at a high flame temperature, which will significantly reduce the life of the sulfur plant and increase the capital and operating cost. However, even with higher flame temperatures, thermal destruction of mercaptans is often incomplete.
It should also be recognized that such plants are typically not selective in the removal of H2S and contaminants. Thus, co-absorption of CO2 by the solvent is often relatively high, which in turn necessitates higher solvent circulation and higher energy consumption. Worse yet, co-absorption also leads to an acid gas rich in CO2, which is undesirable for downstream sulfur plants. Thus, and especially where the feed gas comprises relatively large quantities of mercaptans and other organic sulfurs, capital and operating costs are significantly increased. Additionally, other contaminants (e.g. unsaturated hydrocarbons, oxygen, and sulfur dioxide) may react with the solvent leading to degradation products and reduced solvent performance.
To circumvent at least some of the problems associated with inadequate contaminant removal, various pre- and post treatment methods have been employed. Unfortunately, most of such methods tend to be relatively inefficient and costly, and where contaminants are removed by a fixed bed absorbent process, they may further pose a disposal problem for the spent absorbent. Therefore, various problems associated with operating efficiency, effluents, emissions, and product qualities, particularly in the downstream sulfur plant and tail gas unit, still remain. For example, acid gas produced from such treating processes is generally poor in quality (e.g., comprising significant quantity of contaminants, and/or a relatively large quantity of co-absorbed CO2 and hydrocarbons), which often requires additional processing and higher energy consumption. Furthermore, co-absorbed hydrocarbons in the acid gas must usually be converted to CO2 in the sulfur plant, which results in an increase in CO2 emissions from the process. Thus, despite the significant potential energy value in the hydrocarbons, most of the currently known processes fail to recover these waste hydrocarbon streams as a valuable product.
In still other known processes, a tail gas unit is used to control the sulfur emissions from the sulfur plant. Even if the emission is reduced to a very low ppm level, total quantity of annual sulfur emissions (tons/year) in the vent stream is still relatively high, mostly due to relatively large venting rates, attributed to the large co-absorbed CO2 in the treating process. Moreover, the contaminants and hydrocarbons in the acid gas of most known gas treatment configurations are often not completely destroyed in the sulfur plants, and the sulfur product will therefore be contaminated with unconverted hydrocarbons and mercaptans.
Therefore, while various gas processing treatments and configurations are known in the art, all or almost all of them suffer from one or more disadvantages, and especially where the feed gas comprises relatively high levels of acid gases, hydrocarbons, mercaptans, and organic sulfurs contaminants.